In drilling oil and gas wells, the drilling operator desires to obtain production information on the earth formation of interest. Such information includes the type and quality of fluid (whether liquids or gases) that is produced by the formation, as well as the flow rate and pressure of the fluid. Such information is useful in determining the commercial prospects of the well. A well that shows satisfactory production capability may be completed, while a well that shows no commercial promise is typically plugged and abandoned, with no further drilling expense incurred.
The desired information is typically obtained by drill stem testing. When the drilling extends the borehole into the formation of interest, a drill stem test of the formation maybe initiated. To change over from drilling to a drill stem test, the drill stem is removed from the borehole and the drill bit is taken off. The drill stem is lowered back into the borehole, with a packer and testing equipment at the lower end of the drill stem. The testing equipment is lowered to the formation of interest.
In a conventional drill stem test, the testing equipment is provided with a four phase tool and a hydraulic tool. The four phase tool has a valve that is initially open, while the hydraulic tool has a valve that is initially closed. The valve in the four phase tool is opened and closed by rotating the drill stem in one direction for a specified number of revolutions. The four phase tool can only be actuated for four phases, and no more. The hydraulic tool is opened and closed by putting weight on the drill stem.
The testing equipment has a pressure recorder that operates during the entirety of the drill stem test. The information is recorded on a chart located in the recorder.
After the drill stem is positioned in the borehole, the formation is isolated from the drilling fluid (such as drilling mud) by setting the packer. The packer is set by putting weight on the drill stem. This action also opens the valve in the hydraulic tool, wherein fluid from the formation flows up into the drill stem. The hydraulic tool remains open, and the packer remains set, as long as weight is applied to the drill stem. The period of time where fluid flows into the drill stem is called the initial flow period.
After the initial flow period, the four phase tool is closed by rotating the drill stem a specified number of revolutions (for example, five revolutions). This begins the initial shut-in period, wherein the formation fluid pressure is allowed to increase. The increase in pressure is recorded by the pressure recorder.
After the initial shut-in period, the drill stem is rotated again a specified number of revolutions so as to open the four phase tool. This initiates the second flow period, wherein fluid from the formation enters the drill stem. The second flow period is followed by a second shut-in period, which is begun by rotating the drill stem the specified number of revolutions.
After the second shut-in period, the drill stem is raised to unseat the packer and close the hydraulic tool. Further testing is prohibited because the four phase tool can no longer be opened and closed; the tool has completed its four phases. Occasionally, further drill stem testing may be desired. Therefore, a disadvantage with the conventional drill stem test is a lack of flexibility in conducting extended repetitions of the flow and shut-in periods. If extended repetitions are required, then the four phase tool must be pulled from the borehole and reset at the surface. This adds to the cost of drilling the well.
Another disadvantage occurs in crooked boreholes. Because the four phase tool is opened and closed by rotating the drill stem, it is desirable to have the drill stem not be bound by the sides of the borehole. Unfortunately, in a crooked borehole, rotation of the drill stem may not be possible due to the contact of the drill stem with the sides of the borehole. In such a crooked borehole, a drill stem test cannot be conducted.
Still another disadvantage is the time involved for a drill stem test. A typical drill stem test may take 4.5-6 hours. The information being recorded is located in the pressure recorder at the bottom of the borehole. This information is not available for study until after the test is completed, wherein the testing equipment is pulled to the surface, along with the rest of the drill stem. Furthermore, a sample of the produced fluids is not available for study until the drill stem is pulled to the surface (the produced fluids are in the lower portion of the drill stem due to the flow periods).
In some wells, it becomes immediately apparent upon the retrieval of the information (whether the information is pressure, a fluid sample, etc.) that the well is unproductive. For example, if the well produces salt water or has depleted pressures, then the well is unproductive and will be abandoned. While the drill stem test is being conducted, the drilling equipment stands idled. Yet, the well owner still pays for the drilling equipment, even if idled. Unfortunately, in such unproductive wells, unnecessary expenses are incurred in the form of idled drilling equipment while awaiting the results of the drill stem test. The longer the drill stem test takes to complete, the more expense that is incurred for the idled drilling equipment.
There is in the prior art a downhole tool that transmits the information uphole during the drill stem test. An electrical wireline is used to transmit the information to the surface. Unfortunately, this procedure is very expensive and consequently is not used on many wells.
Once a well has entered into production, the well operator may, from time to time, wish to conduct production tests on that well. When the well is completed for production, a seat nipple is provided just above the packer (the packer isolates the formation). Production tubing extends from the seat nipple up to the surface.
To conduct a production test on the well, a pressure recorder is lowered inside of the tubing to the seat nipple. Then, a surface valve on the tubing is closed to shut in the well. The well is typically shut-in for about 24-72 hours. The test takes a long time because pressure must build up in the tubing from the formation all the way up to the surface. After being shut-in for an extended period of time, the pressure recorder is retrieved to the surface to access the recorded information inside.
The disadvantage to this type of production test is the long period of time needed to conduct the test. A production well may be damaged if it is shut-in for too long. This is because the build up of pressure inside the well could undesirably fracture the formation. As a result, many operators or owners do not subject certain wells to production tests.